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Petroleum Engineering Handbook
Larry W. Lake, Editor-in-Chief
Volume II - Drilling Engineering
Robert F. Mitchell, Editor
Copyright 2006, Society of Petroleum Engineers
Chapter 2 - Drilling Fluids
The drilling-fluid system—commonly known as the "mud system"—is the single component of the well-construction process that remains in contact with the wellbore throughout the entire drilling operation. Drilling-fluid systems are designed and formulated to perform efficiently under expected wellbore conditions. Advances in drilling-fluid technology have made it possible to implement a cost-effective, fit-for-purpose system for each interval in the well-construction process.
The active drilling-fluid system comprises a volume of fluid that is pumped with specially designed mud pumps from the surface pits, through the drillstring exiting at the bit, up the annular space in the wellbore, and back to the surface for solids removal and maintenance treatments as needed. The capacity of the surface system usually is determined by the rig size, and rig selection is determined by the well design. For example, the active drilling-fluid volume on a deepwater well might be several thousand barrels. Much of that volume is required to fill the long drilling riser that connects the rig floor to the seafloor. By contrast, a shallow well on land might only require a few hundred barrels of fluid to reach its objective.
A properly designed and maintained drilling fluid performs several essential functions during well construction:
- Cleans the hole by transporting drilled cuttings to the surface, where they can be mechanically removed from the fluid before it is recirculated downhole.
- Balances or overcomes formation pressures in the wellbore to minimize the risk of well-control issues.
- Supports and stabilizes the walls of the wellbore until casing can be set and cemented or openhole-completion equipment can be installed.
- Prevents or minimizes damage to the producing formation(s).
- Cools and lubricates the drillstring and bit.
- Transmits hydraulic horsepower to the bit.
- Allows information about the producing formation(s) to be retrieved through cuttings analysis, logging-while-drilling data, and wireline logs.
The cost of the drilling fluid averages 10% of the total tangible costs of well construction; however, drilling-fluid performance can affect overall well-construction costs in several ways. A correctly formulated and well-maintained drilling system can contribute to cost containment throughout the drilling operation by enhancing the rate of penetration (ROP), protecting the reservoir from unnecessary damage, minimizing the potential for loss of circulation, stabilizing the wellbore during static intervals, and helping the operator remain in compliance with environmental and safety regulations. Many drilling-fluid systems can be reused from well to well, thereby reducing waste volumes and costs incurred for building new mud.
To the extent possible, the drilling-fluid system should help preserve the productive potential of the hydrocarbon-bearing zone(s). Minimizing fluid and solids invasion into the zones of interest is critical to achieving desired productivity rates. The drilling fluid also should comply with established health, safety, and environmental (HSE) requirements so that personnel are not endangered and environmentally sensitive areas are protected from contamination. Drilling-fluid companies work closely with oil-and-gas operating companies to attain these mutual goals.
Basic Functions of a Drilling Fluid
Transport Cuttings to Surface
Transporting drilled cuttings to surface is the most basic function of drilling fluid. To accomplish this, the fluid should have adequate suspension properties to help ensure that cuttings and commercially added solids such as barite weighing material do not settle during static intervals. The fluid should have the correct chemical properties to help prevent or minimize the dispersion of drilled solids, so that these can be removed efficiently at the surface. Otherwise, these solids can disintegrate into ultrafine particles that can damage the producing zone and impede drilling efficiency.
Prevent Well-Control Issues
The column of drilling fluid in the well exerts hydrostatic pressure on the wellbore. Under normal drilling conditions, this pressure should balance or exceed the natural formation pressure to help prevent an influx of gas or other formation fluids. As the formation pressures increase, the density of the drilling fluid is increased to help maintain a safe margin and prevent "kicks" or "blowouts"; however, if the density of the fluid becomes too heavy, the formation can break down. If drilling fluid is lost in the resultant fractures, a reduction of hydrostatic pressure occurs. This pressure reduction also can lead to an influx from a pressured formation. Therefore, maintaining the appropriate fluid density for the wellbore pressure regime is critical to safety and wellbore stability.
Preserve Wellbore Stability
Maintaining the optimal drilling-fluid density not only helps contain formation pressures, but also helps prevent hole collapse and shale destabilization. The wellbore should be free of obstructions and tight spots, so that the drillstring can be moved freely in and out of the hole (tripping). After a hole section has been drilled to the planned depth, the wellbore should remain stable under static conditions while casing is run to bottom and cemented. The drilling-fluid program should indicate the density and physicochemical properties most likely to provide the best results for a given interval.
Minimize Formation Drainage
Drilling operations expose the producing formation to the drilling fluid and any solids and chemicals contained in that fluid. Some invasion of fluid filtrate and/or fine solids into the formation is inevitable; however, this invasion and the potential for damage to the formation can be minimized with careful fluid design that is based on testing performed with cored samples of the formation of interest. Formation damage also can be curtailed by expert management of downhole hydraulics using accurate modeling software, as well as by the selection of a specially designed "drill-in" fluid, such as the systems that typically are implemented while drilling horizontal wells.
Cool and Lubricate the Drillstring
The bit and drillstring rotate at relatively high revolutions per minute (rev/min) all or part of the time during actual drilling operations. The circulation of drilling fluid through the drillstring and up the wellbore annular space helps reduce friction and cool the drillstring. The drilling fluid also provides a degree of lubricity to aid the movement of the drillpipe and bottomhole assembly (BHA) through angles that are created intentionally by directional drilling and/or through tight spots that can result from swelling shale. Oil-based fluids (OBFs) and synthetic-based fluids (SBFs) offer a high degree of lubricity and for this reason generally are the preferred fluid types for high-angle directional wells. Some water-based polymer systems also provide lubricity approaching that of the oil- and synthetic-based systems.
Provide Information About the Wellbore
Because drilling fluid is in constant contact with the wellbore, it reveals substantial information about the formations being drilled and serves as a conduit for much data collected downhole by tools located on the drillstring and through wireline-logging operations performed when the drillstring is out of the hole. The drilling fluid’s ability to preserve the cuttings as they travel up the annulus directly affects the quality of analysis that can be performed on the cuttings. These cuttings serve as a primary indicator of the physical and chemical condition of the drilling fluid. An optimized drilling-fluid system that helps produce a stable, in-gauge wellbore can enhance the quality of the data transmitted by downhole measurement and logging tools as well as by wireline tools.
Minimize Risk to Personnel, the Environment, and Drilling Equipment
Drilling fluids require daily testing and continuous monitoring by specially trained personnel. The safety hazards associated with handling of any type of fluid are clearly indicated in the fluid’s documentation. Drilling fluids also are closely scrutinized by worldwide regulatory agencies to help ensure that the formulations in use comply with regulations established to protect both natural and human communities where drilling takes place. At the rigsite, the equipment used to pump or process fluid is checked constantly for signs of wear from abrasion or chemical corrosion. Elastomers used in blowout-prevention equipment are tested for compatibility with the proposed drilling-fluid system to ensure that safety is not compromised.
The upper hole sections typically are drilled with low-density water-based fluids (WBFs). Depending on formation types, downhole temperatures, directional-drilling plans, and other factors, the operator might switch to an OBF or SBF at a predetermined point in the drilling process. High-performance WBFs also are available to meet a variety of drilling challenges.
Depending on the location of the well, the drilling-fluid system can be exposed to saltwater flows, influxes of carbon dioxide and hydrogen sulfide, solids buildup, oil or gas influxes, or extreme temperatures at both ends of the scale—or all of these. Contamination also comes from contact with the spacers and cement slurries used to permanently install casing and in the course of displacing from one drilling-fluid system to another.
The drilling-fluid specialists who prepare drilling-fluid programs should be aware of the operational and environmental challenges posed by any well. Working closely with the operator, the specialist (who typically is supported by technical experts and a research staff) can plan for the scope of conditions that are likely to be encountered and generate a program that is both safe and cost-effective. The planning stage usually includes the identification of specific performance objectives and the means by which success will be measured.
Throughout the well-construction process, the drilling-fluid personnel assigned to the operation maintain accurate records of test results, fluid volumes, drilling events, product inventory, and actions related to achieving environmental compliance. The standard drilling-mud report reflects the type of information the drilling-fluid personnel (often called "mud engineers") provide at the rig site on a daily basis. These reports, often computer-generated and stored in a database, and the post-well analysis performed at the conclusion of the well serve as reference materials for future wells in the same area or wells that present similar challenges.
Types of Drilling Fluids
World Oil’s annual classification of fluid systems lists nine distinct categories of drilling fluids, including freshwater systems, saltwater systems, oil- or synthetic-based systems, and pneumatic (air, mist, foam, gas) "fluid" systems. Three key factors usually determine the type of fluid selected for a specific well: cost, technical performance, and environmental impact.
Water-based fluids are the most widely used systems and generally are considered less expensive than OBFs or SBFs. The OBFs and SBFs—also known as invert-emulsion systems—have an oil or synthetic base fluid as the continuous, or external, phase and brine as the internal phase. Whereas invert-emulsion systems have a higher cost per unit than most water-based fluids, they often are selected when well conditions call for reliable shale inhibition and/or excellent lubricity. Water-based systems and invert-emulsion systems can be formulated to tolerate relatively high downhole temperatures. Pneumatic systems most commonly are implemented in areas where formation pressures are relatively low and the risk of lost circulation or formation damage is relatively high. The use of these systems requires specialized pressure-management equipment to help prevent the development of hazardous conditions when hydrocarbons are encountered.
Water-based fluids are used to drill approximately 80% of all wells. The base fluid may be fresh water, seawater, brine, saturated brine, or a formate brine. The type of fluid selected depends on anticipated well conditions or on the specific interval of the well being drilled. For example, the surface interval typically is drilled with a low-density water- or seawater-based mud that contains few commercial additives. These systems incorporate natural clays in the course of the drilling operation. Some commercial bentonite or attapulgite also may be added to aid in fluid-loss control and to enhance hole-cleaning effectiveness. After surface casing is set and cemented, the operator often continues drilling with a WBF unless well conditions require displacing to an oil- or synthetic-based system.
WBFs fall into two broad categories: nondispersed and dispersed. Simple gel-and-water systems used for tophole drilling are nondispersed, as are many of the advanced polymer systems that contain little or no bentonite. The natural clays that are incorporated into nondispersed systems are managed through dilution, encapsulation, and/or flocculation. A properly designed solids-control system can be used to remove fine solids from the mud system and help maintain drilling efficiency. The low-solids, nondispersed (LSND) polymer systems rely on high- and low-molecular-weight long-chain polymers to provide viscosity and fluid-loss control. Low-colloidal solids are encapsulated and flocculated for more efficient removal at the surface, which in turn decreases dilution requirements. Specially developed high-temperature polymers are available to help overcome gelation issues that might occur on high-pressure, high-temperature (HP/HT) wells. With proper treatment, some LSND systems can be weighted to 17.0 to 18.0 ppg and run at 350°F and higher.
Dispersed systems are treated with chemical dispersants that are designed to deflocculate clay particles to allow improved rheology control in higher-density muds. Widely used dispersants include lignosulfonates, lignitic additives, and tannins. Dispersed systems typically require additions of caustic soda (NaOH) to maintain a pH level of 10.0 to 11.0. Dispersing a system can increase its tolerance for solids, making it possible to weight up to 20.0 ppg. The commonly used lignosulfonate system relies on relatively inexpensive additives and is familiar to most operator and rig personnel. Additional commonly used dispersed muds include lime and other cationic systems. A solids-laden dispersed system also can decrease the rate of penetration significantly and contribute to hole erosion.
Saltwater drilling fluids often are used for shale inhibition and for drilling salt formations. They also are known to inhibit the formation of ice-like hydrates that can accumulate around subsea wellheads and well-control equipment, blocking lines and impeding critical operations. Solids-free and low-solids systems can be formulated with high-density brines, such as calcium chloride, calcium bromide, zinc bromide, and potassium and cesium formate.
Drill-In Fluids (DIFs)
Too often, drilling into a pay zone with a conventional fluid can introduce a host of previously undefined risks, all of which diminish reservoir connectivity with the wellbore or reduce formation permeability. This is particularly true in horizontal wells, where the pay zone can be exposed to the drilling fluid over a long interval. Selecting the most suitable fluid system for drilling into the pay zone requires a thorough understanding of the reservoir. Using data generated by lab testing on core plugs from carefully selected pay zone cores, a reservoir-fluid-sensitivity study should be conducted to determine the morphological and mineralogical composition of the reservoir rock. Natural reservoir fluids should be analyzed to establish their chemical makeup. The degree of damage that could be caused by anticipated problems can be modeled, as can the effectiveness of possible solutions for mitigating the risks.
A DIF is a clean fluid that is designed to cause little or no loss of the natural permeability of the pay zone and to provide superior hole cleaning and easy cleanup. DIFs can be water-based, brine-based, oil-based, or synthetic-based systems. In addition to being safe and economical for the application, a DIF should be compatible with the reservoir’s native fluids to avoid causing precipitation of salts or production of emulsions. A suitable nondamaging fluid should establish a filter cake on the face of the formation, but should not penetrate too far into the formation pore pattern. The fluid filtrate should inhibit or prevent swelling of reactive clay particles within the pore throats.
Formation damage commonly is caused by pay zone invasion and plugging by fine particles, formation clay swelling, commingling of incompatible fluids, movement of dislodged formation pore-filling particles, changes in reservoir-rock wettability, and formation of emulsions or water blocks. Once a damage mechanism has diminished the permeability of a reservoir, it seldom is possible to restore the reservoir to its original condition.
Oil-based systems were developed and introduced in the 1960s to help address several drilling problems: formation clays that react, swell, or slough after exposure to WBFs; increasing downhole temperatures; contaminants; and stuck pipe and torque and drag.
Oil-based fluids in use today are formulated with diesel, mineral oil, or low-toxicity linear paraffins (that are refined from crude oil). The electrical stability of the internal brine or water phase is monitored to help ensure that the strength of the emulsion is maintained at or near a predetermined value. The emulsion should be stable enough to incorporate additional water volume if a downhole water flow is encountered.
Barite is used to increase system density, and specially-treated organophilic bentonite is the primary viscosifier in most oil-based systems. The emulsified water phase also contributes to fluid viscosity. Organophilic lignitic materials are added to help control low-pressure/low-temperature (LP/LT) and HP/HT fluid loss. Oil-wetting is essential for ensuring that particulate materials remain in suspension; the surfactants used for oil-wetting also can work as thinners. Oil-based systems usually contain lime to maintain an elevated pH, resist adverse effects of hydrogen sulfide (H2S) and carbon dioxide (CO2) gases, and enhance emulsion stability.
Shale inhibition is one of the key benefits of using an oil-based system. The high-salinity-water phase helps to prevent shales from hydrating, swelling, and sloughing into the wellbore. Most conventional oil-based mud (OBM) systems are formulated with calcium-chloride brine, which appears to offer the best inhibition properties for most shales.
The ratio of the oil percentage to the water percentage in an oil-based system is called its oil/water ratio. Oil-based systems generally function well with an oil/water ratio of from 65/35 to 95/5, but the most commonly observed range is from 80/20 to 90/10.
The discharge of whole fluid or cuttings generated with OBFs is not permitted in most offshore-drilling areas. All such drilled cuttings and waste fluid are processed and shipped to shore for disposal. Whereas many land wells continue to be drilled with diesel-based fluids, the development of SBFs in the late 1980s provided new options to offshore operators who depend on the drilling performance of oil-based systems to help hold down overall drilling costs but require more environmentally-friendly fluids.
Synthetic-Based Drilling Fluids
Synthetic-based fluids were developed out of an increasing desire to reduce the environmental impact of offshore drilling operations, but without sacrificing the cost-effectiveness of oil-based systems.
Like traditional OBFs, SBFs help maximize ROPs, increase lubricity in directional and horizontal wells, and minimize wellbore-stability problems such as those caused by reactive shales. Field data gathered since the early 1990s confirm that SBFs provide exceptional drilling performance, easily equaling that of diesel- and mineral-oil-based fluids.
In many offshore areas, regulations that prohibit the discharge of cuttings drilled with OBFs do not apply to some of the synthetic-based systems. SBFs’ cost per barrel can be higher, but they have proved economical in many offshore applications for the same reasons that traditional OBFs have: fast penetration rates and less mud-related nonproductive time (NPT). SBFs that are formulated with linear alphaolefins (LAO) and isomerized olefins (IO) exhibit the lower kinematic viscosities that are required in response to the increasing importance of viscosity issues as operators move into deeper waters. Early ester-based systems exhibited high kinematic viscosity, a condition that is magnified in the cold temperatures encountered in deepwater risers. However, a shorter-chain-length (C8), low-viscosity ester that was developed in 2000 exhibits viscosity similar to or lower than that of the other base fluids, specifically the heavily used IO systems. Because of their high biodegradability and low toxicity, esters are universally recognized as the best base fluid for environmental performance.
By the end of 2001, deepwater wells were providing 59% of the oil being produced in the Gulf of Mexico. Until operators began drilling in these deepwater locations, where the pore pressure/fracture gradient (PP/FG) margin is very narrow and mile-long risers are not uncommon, the standard synthetic formulations provided satisfactory performance. However, the issues that arose because of deepwater drilling and changing environmental regulations prompted a closer examination of several seemingly essential additives.
When cold temperatures are encountered, conventional SBFs might develop undesirably high viscosities as a result of the organophilic clay and lignitic additives in the system. The introduction of SBFs formulated with zero or minimal additions of organophilic clay and lignitic products allowed rheological and fluid-loss properties to be controlled through the fluid-emulsion characteristics. The performance advantages of these systems include high, flat gel strengths that break with minimal initiation pressure; significantly lower equivalent circulating densities (ECDs); and reduced mud losses while drilling, running casing, and cementing.
Normally, the high-salinity water phase of an invert-emulsion fluid helps to stabilize reactive shale and prevent swelling; however, drilling fluids that are formulated with diesel- or synthetic-based oil and no water phase are used to drill long shale intervals where the salinity of the formation water is highly variable. By eliminating the water phase, the all-oil drilling fluid can preserve shale stability throughout the interval.
Compressed air or gas can be used in place of drilling fluid to circulate cuttings out of the wellbore. Pneumatic fluids fall into one of three categories: air or gas only, aerated fluid, or foam. Pneumatic-drilling operations require specialized equipment to help ensure safe management of the cuttings and formation fluids that return to surface, as well as tanks, compressors, lines, and valves associated with the gas used for drilling or aerating the drilling fluid or foam.
Except when drilling through high-pressure hydrocarbon- or fluid-laden formations that demand a high-density fluid to prevent well-control issues, using pneumatic fluids offers several advantages: little or no formation damage, rapid evaluation of cuttings for the presence of hydrocarbons, prevention of lost circulation, and significantly higher penetration rates in hard-rock formations.
Drilling-fluid service companies provide a wide range of additives that are designed to prevent or mitigate costly well-construction delays. Examples of these products include:
- Lost-circulation materials (LCM) that help to prevent or stop downhole mud losses into weak or depleted formations.
- Spotting fluids that help to free stuck pipe.
- Lubricants for WBFs that ease torque and drag and facilitate drilling in high-angle environments.
- Protective chemicals (e.g., scale and corrosion inhibitors, biocides, and H2S scavengers) that prevent damage to tubulars and personnel.
Many types of LCM are available to address loss situations. Sized calcium carbonate, mica, fibrous material, cellophane, and crushed walnut shells have been used for decades. The development of deformable graphitic materials that can continuously seal off fractures under changing pressure conditions has allowed operators to cure some types of losses more consistently. The application of these and similar materials to actually strengthen the wellbore has proved successful. Hydratable and rapid-set lost-circulation pills also are effective for curing severe and total losses. Some of these fast-acting pills can be mixed and pumped with standard rig equipment. Others require special mixing and pumping equipment.
Most spotting fluids are designed to penetrate and break up the wall cake around the drillstring. A soak period usually is required to achieve results. Spotting fluids typically are formulated with a base fluid and additives that can be incorporated into the active mud system with no adverse effects after the pipe is freed and/or circulation resumes.
Lubricants might contain hydrocarbon-based materials or can be formulated specifically for use in areas where environmental regulations prohibit the use of an oil-based additive. Tiny glass or polymer beads also can be added to the drilling fluid to increase lubricity. Lubricants are designed to reduce friction in metal-to-metal contact and to provide lubricity to the drillstring in the open hole, especially in deviated wells, where the drillstring is likely to have continuous contact with the wellbore.
Corrosion, Inhibitors, Biocides, and Scavengers.
Corrosion causes the majority of drillpipe loss and also damages casing, mud pumps, bits, and downhole tools. As downhole temperatures increase, corrosion also increases at a corresponding rate if the drillstring is not protected by chemical treatment. Abrasive materials in the drilling fluid can accelerate corrosion by scouring away protective films. Corrosion typically is caused by one or more factors that include exposure to oxygen, H2S, and/or CO2; bacterial activity in the drilling fluid; high-temperature environments; and contact with sulfur-containing materials. Drillstring coupons can be inserted between joints of drillpipe as the pipe is tripped in the hole. When the pipe next is tripped out of the hole, the coupon can be examined for signs of pitting and corrosion to determine whether the drillstring components are undergoing similar damage.
H2S and CO2 frequently are present in the same formation. Scavenger and inhibitor treatments should be designed to counteract both gases if an influx occurs because of underbalanced drilling conditions. Maintaining a high pH helps control H2S and CO2 and prevents bacteria from souring the drilling fluid. Bacteria also can be controlled using a microbiocide additive.
Field TestsThe drilling-fluids specialist in the field conducts a number of tests to determine the properties of the drilling-fluid system and evaluate treatment needs. Although drilling-fluid companies might use some tests that are designed for evaluating a proprietary product, the vast majority of field tests are standardized according to American Petroleum Institute Recommended Practices (API RP) 13B-1 and 13B-2, for WBFs and OBFs, respectively.
Table 2.1 shows typical API-recommended field tests for WBFs. Table 2.2 shows typical API-recommended field tests for OBFs and SBFs. Several tests are identical to those performed on WBFs. For all three fluid types, depending on the type of fluid in use, some or all tests should be performed.
Extensive testing of the fluid is performed in the design phase of the fluid, either to achieve desired fluid characteristics or to determine the performance limitations of the fluid.
Laboratory testing aids in fluid design and expands the capacity to monitor and evaluate fluids when field-testing procedures prove inadequate. Some laboratory tests are identical to field-testing methods, whereas others are unique to the laboratory environment. In the laboratory setting, testing and equipment are available to determine toxicity, fluid rheology, fluid loss, particle plugging, high-angle sag, dynamic high-angle sag, high-temperature fluid aging, cuttings erosion, shale stability, capillary suction, lubricity, return permeability, X-ray diffraction, and particle-size distribution (PSD).
The environmental and toxicity standards of the region in which the fluid is being used will require testing either of the whole drilling fluid or of its individual components. Toxicity tests generally are used for offshore applications. An approved laboratory can perform the proper testing to ensure compliance of the fluid or its components.
Fluid rheology is an important parameter of drilling-fluid performance. For critical offshore applications with extreme temperature and pressure requirements, the viscosity profile of the fluid often is measured with a controlled-temperature and -pressure viscometer (e.g., the Fann 75). Fluids can be tested at temperatures of < 35°F to 500°F, with pressures of up to 20,000 psia. Cold-fluid rheology is important because of the low temperatures that the fluid is exposed to in deepwater risers. High temperatures can be encountered in deep wells or in geothermally heated wells. The fluid can be under tremendous pressure downhole, and its viscosity profile can change accordingly.
If fluid (or filtration) loss is excessive, formation instability, formation damage, or a fractured formation and loss of drilling fluid can occur. In the field, LP/LT and HP/HT fluid-loss tests are performed routinely. Fluid loss also can be measured under dynamic conditions using the Fann 90 viscometer, which incorporates a rotating bob to provide fluid shear in the center of a ceramic-filter core. The fluid is heated and pressurized. Fluid loss is measured radially through the entire core, giving a sophisticated simulation of the drilling fluid circulating in the wellbore.
The particle-plugging test (PPT) often is used to evaluate the ability of plugging particles added to a fluid to mitigate formation damage by stopping or slowing filtrate invasion into a core. A PPT uses an inverted HP/HT-filter-press cell that has been fitted with a ceramic disk as a filtering medium and is pressurized with a hydraulic cylinder. Ceramic disks with different mean pore-throat diameters are used to simulate a wellbore wall. A PPT typically is run with a 2,000-psi or higher differential pressure. The spurt loss and total fluid loss are measured over a 30-minute period. The cell is inverted, and fluid loss is measured from the top of the cell to eliminate the effects of fluid settling.
High-Angle Sag and Dynamic High-Angle Sag
The weighting material used to increase the density of the drilling fluid can settle at a faster rate in an angled well than in a vertical well. The high-angle sag test (HAST) and dynamic high-angle sag test (DHAST) measure density differences in the fluid as the angle of drilling changes. The HAST is used with fluids under static conditions, whereas the DHAST is used under dynamic conditions, in which the fluid can be subjected to shear or observed statically. The DHAST has temperature and pressure specifications of 350°F and 10,000 psia, respectively. Measuring the changes in density allows the fluid’s propensity to undergo these changes in the drilling process to be evaluated and curtailed by modifications to the fluid design.
High-Temperature Fluid Aging
Over time, high temperatures can degrade the components of a drilling fluid and alter its performance. High-temperature aging of the fluid is conducted to assess the impact that temperatures> 250°F have on performance. Fluid can be aged statically and dynamically. In the static-aging process, the fluid is placed in a pressurized cell and allowed to stand without rolling at the desired test temperature for a desired length of time (rarely<
If drilled cuttings undergo significant erosion before being removed from the drilling fluid, that fluid’s colloidal content can increase and interfere with drilling performance. Also, cuttings erosion usually is accompanied by wellbore erosion, which leads to hole washout. Two tests are available to aid in designing fluids that reduce cuttings erosion. One is an API-approved method in which the user measures out a known amount of shale material that is representative of the formation to be drilled and that has been broken and sized between No. 6 and No. 12 shaker screens. The shale then is placed in a jar and exposed to the drilling fluid, where it is aged by hot-rolling it at 150°F for 16 hours. After aging, the shale is collected on the No. 12 shaker screen, carefully washed, and dried. The percent recovery then is calculated on the basis of the weight of the recovered shale vs. that of the shale originally used. Variations of this method are used for individual component testing. The aging time is varied to determine the erosion rate.
The second available test is the slake-durability tester, which measures chemical and mechanical erosion to the shale. This tester resembles the API-approved method in that it uses a known amount of test shale and in that recovery is calculated in the same way. It differs in that the shale sample is placed inside a mesh-screen cage that is immersed in the drilling fluid and rolled continually throughout the test.
Reactive shales cause many difficulties in a drilling operation. Fluids should be designed to mitigate these shale problems. Along with erosion testing, four other distinct tests are used to assess the interaction between the drilling fluid and shale: capillary suction time (CST), return permeability, X-ray diffraction and PSD.
The CST test investigates the chemical effects of the drilling fluid on the dispersive properties of shale and active clays. The CST test measures filter-cake permeability by timing the capillary action of filtrate onto a paper medium. Changes in permeability then can be related to the inhibitive characteristics of the fluid.
When drilling reaches a hydrocarbon-bearing zone, of great concern is the potential to damage the formation and thereby to reduce the ability of the well to produce hydrocarbons. A return-permeability test can reveal formation damage and can be conducted using a return permeameter. The porosity and conductivity of a core sample are determined by flowing a refined mineral oil through the core. To simulate fluid and filtrate invasion into the core, drilling fluid then is placed against the outflow side of the core, and differential pressure is applied in the direction opposite that of the previous flow measurement. After contamination, mineral oil again is flowed through the core in the original direction, and the resultant porosity is compared to the original porosity to determine whether a reduction in permeability has occurred.
Knowing the mineral composition of a formation to be drilled is important for determining how the drilling fluid will react with the formation and how to prevent potential drilling problems. Fluid labs use X-ray diffraction to determine the mineralogical composition of shale or cuttings. They expose a crystalline mineral sample to X-ray radiation and then compare the resultant diffraction pattern to known standards to determine which minerals are present in the sample.
Particle-size distributions are determined for various solid materials that are added to drilling fluids. A particle-size analyzer determines PSD by measuring laser-light diffraction, which then can be related to particle size. PSDs are used to determine what screen size is needed for removing particles from the fluid system for conditioning, whether the particles present are small enough to cause formation damage by becoming trapped in the formation’s pores, and whether the present distribution of particle sizes will allow effective bridging of pore openings to help control fluid loss without causing excessive formation damage.
Challenges Related to Drilling Fluid
All drilling challenges relate to the fundamental objective of maintaining a workable wellbore throughout the well-construction process. A workable wellbore can be drilled, logged, cased, cemented, and completed with minimal nonproductive time. The design of the drilling-fluid system is central to achieving this objective.
Most operational problems are interrelated, making them more difficult to resolve. For example, loss of circulation into a depleted zone causes a drop in hydrostatic pressure in the wellbore. When the hydrostatic pressure falls too low to hold back formation fluids, the loss incident can be compounded by an influx of gas or water, known as a flow or (when more severe) a kick. In these circumstances, the operator should increase the fluid density to stop the kick, yet avoid exacerbating the lost-circulation problem. Furthermore, the pressure differential created at the loss zone can cause the drillstring to become embedded in the wall cake, a situation called differential sticking. The drillstring should be freed quickly by mechanical or chemical methods because the longer it remains stuck, the lower the likelihood of freeing it. Failure to free the pipe can require an expensive fishing job that cannot be undertaken until the well is under control.
Another example of interrelated problems occurs when the directional-drilling operation requires an interval of sliding, in which the drillstring is not rotated for a period of time but drilling continues by means of a downhole motor. Sliding allows better directional control, but the lack of pipe rotation can impair hole cleaning. Good hole cleaning is important in all wells, but it is critical in high-angle wells, in which cuttings might fall to the low side of the wellbore and form deep cuttings beds. Failure to remove the cuttings can lead to packing off of the drillstring—another version of stuck pipe. If the drillstring is severely packed off, attempts to circulate drilling fluid might lead to excessive pressure on the wellbore, which in turn can cause the formation below the packoff to break down.
Incidents like these are not uncommon. The drilling fluid alone cannot correct all problems, but skillful management of the drilling-fluid system by a specialist can prevent conditions that lead to wellbore instability, thereby helping the operator to achieve a workable wellbore.
Loss of Circulation
A lost-circulation incident exacts a heavy cost that goes far beyond the price of products that are used to treat it. Lost circulation always causes nonproductive time that includes the cost of rig time and all the services that support the drilling operation. Losing mud into the oil or gas reservoir can drastically reduce or even eliminate the operator’s ability to produce the zone. Prevention is critical, but because lost circulation is such a common occurrence, effective methods of remediation are also a high priority.
Rock mechanics and hydraulic-fracture theory indicate that it is easier to prevent fracture propagation than it is to plug the fracture later to prevent fluid from re-entering. Because of the high cost of most weighted, treated drilling-fluid systems, LCM routinely is carried in the active system on many operations in which probable lost-circulation zones exist, such as in a "rubble" zone beneath salt or in a known depleted zone. Other conditions that are prone to loss of circulation include natural and induced fractures, formations with high permeability and/or high porosity, and vugular formations (e.g., limestone and chalk). Using an LCM that can be carried in the drilling fluid without significantly affecting its rheology or fluid-loss characteristics facilitates the preventive pretreatment. Pretreatment can mitigate wellbore breathing (ballooning), seepage losses, and/or potential lost circulation when drilling depleted zones.
When a loss zone is encountered, the top priority is keeping the hole full so that the hydrostatic pressure does not fall below formation pressure and allow a kick to occur. The hydrostatic pressure may be purposely reduced to stop the loss, as long as sufficient density is maintained to prevent well-control problems. Loss zones also pose a high risk of differential sticking. Rotating and reciprocating the drillstring helps reduce this risk while an LCM treatment is prepared. If the location of the loss zone is known, it might be advisable to pull the drillstring to above the affected area.
A variety of LCM is available, and combining several types and particle sizes for treatment purposes is common practice. Conventional—and relatively inexpensive—materials include sized calcium carbonate, paper, cottonseed hulls, nutshells, mica, and cellophane. Because lost circulation always has been one of the most costly issues facing the industry, a focus on healing the loss zone quickly and safely encouraged the development of proprietary materials that conform to the fracture to seal off pores, regardless of changes in annular pressure. In some cases, such deformable, expanding LCM is pumped ahead of cement jobs in which losses are expected. This type of material has a comparatively high success rate for the prevention and remediation of severe losses.
Severe lost-circulation problems that do not respond to conventional treatments might be curable by spotting a hydratable LCM pill and holding it under gentle squeeze pressure for a predetermined period. At downhole temperatures, the LCM pill expands rapidly to fill and bridge fractures, allowing drilling and cementing operations to resume quickly, sometimes in 4 hours or less. Alternatively, rapid-set LCM products are available that react quickly with the drilling fluid after being spotted across the loss zone and form a dense, flexible plug that fills the fracture and adheres to the wellbore. In some cases, this type of plug has proved so effective that the natural fracture gradient of the formation actually increased, allowing the operator to resume drilling and increase the mud weight beyond constraints established before the treatment.
Leakoff Test (LOT)
Conducting an accurate leakoff test is fundamental to preventing lost circulation. The LOT is performed by closing in the well and pressuring up in the open hole immediately below the last string of casing before drilling ahead in the next interval. On the basis of the point at which the pressure drops off, the test indicates the strength of the wellbore at the casing seat, typically considered one of the weakest points in any interval. However, extending an LOT to the fracture-extension stage can seriously lower the maximum mud weight that may be used to safely drill the interval without lost circulation. Consequently, stopping the test as early as possible after the pressure plot starts to break over is preferred.
Formation Integrity Test (FIT)
To avoid breaking down the formation, many operators perform an FIT at the casing seat to determine whether the wellbore will tolerate the maximum mud weight anticipated while drilling the interval. If the casing seat holds pressure that is equivalent to the prescribed mud density, the test is considered successful and drilling resumes.
When an operator chooses to perform an LOT or an FIT, if the test fails, some remediation effort—typically a cement squeeze—should be carried out before drilling resumes to ensure that the wellbore is competent.
Stuck PipeComplications related to stuck pipe can account for nearly half of total well cost, making stuck pipe one of the most expensive problems that can occur during a drilling operation. Stuck pipe often is associated with well-control and lost-circulation events—the two other costly disruptions to drilling operations—and is a significant risk in high-angle and horizontal wells.
Drilling through depleted zones, where the pressure in the annulus exceeds that in the formation, might cause the drillstring to be pulled against the wall and embedded in the filter cake deposited there (Fig. 2.1). The internal cake pressure decreases at the point where the drillpipe contacts the filter cake, causing the pipe to be held against the wall by differential pressure. In high-angle and horizontal wells, gravitational force contributes to extended contact between the drillstring and the formation. Properly managing the lubricity of the drilling fluid and the quality of the filter cake across the permeable formation can help reduce occurrences of stuck pipe.
Fig. 2.1—Principle of differential sticking (modified from Santos.
Mechanical causes for stuck pipe include keyseating, packoff from poor hole-cleaning, shale swelling, wellbore collapse, plastic-flowing formation (i.e., salt), and bridging. Preventing stuck pipe can require close monitoring of early warning signs, such as increases in torque and drag, indications of excessive cuttings loading, encountering tight spots while tripping, and experiencing loss of circulation while drilling.
Depending on what the suspected cause of sticking is, it might be necessary to increase the drilling-fluid density (to stabilize a swelling shale) or to decrease it (to protect the depleted zone and avoid differential sticking). A drilling fluid’s friction coefficient is an important factor in its effectiveness in preventing stuck pipe and/or enabling stuck pipe to be worked free. OBFs and SBFs offer the maximum lubricity; inhibitive WBFs can be treated with a lubricant (typically 1 to 5% by volume) and formulated to produce a thin, impermeable filter cake that offers increased protection against sticking. High-performance-polymer WBFs that are designed specifically to serve as alternates to OBFs and SBFs exhibit a high degree of natural lubricity and might not require the addition of a lubricant.
Lubricants for WBFs
The quality of the emulsion is important to a lubricant’s performance in WBF. If the lubricant is too tightly emulsified, it no longer functions as a lubricant. If the emulsion is too loose, there is a risk that the lubricant will destabilize into a stringy, semisolid material. Overtreatment with lubricants might cause flocculation of the drilling fluid because of oil-wet solids.
Film strength is the main indicator of lubricant performance; generally, the higher the strength, the better the lubricant performance. However, environmental issues might arise with the use of certain high-film-strength lubricants. For this reason, alcohol/glycol-type lubricants, considered to be more environmentally friendly, have gained popularity. The alcohol/glycol lubricants also might perform better at low temperatures. The typical operating range for alcohol/glycol lubricants is 40 to 350°F.
Maximum film strength is required under high-pressure conditions and where elevated torque and drag measurements indicate a high risk of stuck pipe. Sulfurized oils (e.g., sulfurized olefin) have proved effective under these conditions. High-film-strength lubricants generally demonstrate increased thermal stability.
Other lubricant types include glass, plastic, and ceramic beads.
Spotting fluids that are used to free stuck pipe are formulated to first crack the filter cake and then provide sufficient lubricity to allow the pipe to be worked free. Time is the key factor in successfully freeing stuck pipe. Spotting fluids routinely are included in rigsite inventory so that the spotting fluid can be applied as soon as possible after the pipe sticks, ideally within 6 hours. The length of free pipe may be estimated on the basis of drillstring stretch measurements, allowing the operator to determine the stuck point and deliver the spotting fluid as accurately as possible. If circulation is possible, decreasing the drilling-fluid density might relieve differential sticking; however, stuck pipe might be caused by a well kick combined with loss of circulation in a higher zone, which would eliminate the option of an intentional reduction in mud weight.
Shales make up the majority of drilled formations and cause most wellbore-instability problems, ranging from washout to complete collapse of the hole. Shales are fine-grained sedimentary rocks composed of clay, silt, and, in some cases, fine sand. Shale types range from clay-rich gumbo (relatively weak) to shaly siltstone (highly cemented) and have in common the characteristics of extremely low permeability and a high proportion of clay minerals.
Drilling overbalanced through a shale formation with a WBF allows drilling-fluid pressure to penetrate the formation. Because of the saturation and low permeability of the formation, the penetration of a small volume of mud filtrate into the formation causes a considerable increase in pore-fluid pressure near the wellbore wall. The increase in pore-fluid pressure reduces the effective mud support, which can cause instability. Several polymer WBF systems have made shale-inhibition gains on OBFs and SBFs through the use of powerful inhibitors and encapsulators that help prevent shale hydration and dispersion.
Effective drilling-fluid selection and management is important to the successful outcome of a high-angle or horizontal extended-reach drilling (ERD) operation. In addition to formation protection, the most important ERD challenges include the narrow margin between the pore pressure and the fracture gradient, ECD management, adequate hole cleaning, reduction of torque and drag, wellbore stability, barite sag, and loss of circulation. Years of operational data indicate that hole angles of between 30 and 60° create the most difficult hole-cleaning conditions. Good management of annular velocities, drilling-fluid viscosity, pipe-rotation speed, and pipe eccentricity can help minimize hole-cleaning problems.
Because of their reliable performance under adverse downhole conditions, invert-emulsion drilling fluids (OBFs and SBFs) usually are the first choice for ERD operations; however, the use of invert-emulsion muds is becoming more restricted because of environmental considerations, and several inhibitive WBF systems have been developed for use as alternatives.
Using hydraulics-modeling software that is programmed specifically for oilfield applications, it is possible to accurately predict drilling-fluid properties under actual downhole conditions, including static and dynamic temperature profiles, hydraulic pressures, ECD, annular pressure loss, rheological properties, cuttings loading and transport efficiency, effects of pipe eccentricity, and pressures required to break gels. The modeled properties are confirmed by real-time pressure-while-drilling (PWD) data. The immediate feedback from the modeling process can allow the operator to optimize hole cleaning by several means, including:
- Adjustment of surface mud properties to meet changing downhole conditions.
- Adjustment of mechanical parameters such as penetration rate, flow rate, pipe-rotation speed, and tripping speed.
- Design and implementation of an effective sweep program.
Even while still in the well-planning stages, the casing design, bit selection, and drilling-fluid properties can be optimized to achieve the best drilling conditions, given the rig’s pumps and fluid-handling capabilities. An accurate hydraulics modeling package should incorporate Bingham-plastic, power-law, and the Herschel-Bulkley rheological models. Surface rheological properties are measured with a six-speed rheometer; such input allows the hydraulics-modeling software to determine actual annular shear rates at any depth in the well, taking into account the temperature and pressure regime at that depth.
The basis for the rheological modeling is either a matrix database of rheometer data or real-time data obtained from an HP/HT viscometer while drilling. A built-in routine can calculate the pressure required to break gels, allowing the operator to minimize surge pressures while tripping and running casing and to reduce the risk of breaking down the formation.
A comprehensive modeling software package also should accurately predict the cuttings loading in the annulus, the cuttings-bed height, the effect of drillstring rotary speed and pipe eccentricity, and the maximum recommended ROP for the given conditions.
These tools are useful not only for drilling extended-reach wells, but also for optimizing drilling performance in deepwater operations, HP/HT wells, and slimhole-drilling operations.
High-viscosity sweeps that provide effective hole-cleaning in vertical wellbores might not be the best option for high-angle and horizontal wells because of the flow distribution around eccentric drillpipe. To induce flow, the stress applied to a fluid must exceed that fluid’s yield stress. In the narrow annular space created by eccentric drillpipe, it is possible that little or no flow will occur and that the cuttings bed will remain in place. Pumping a high-viscosity sweep might exacerbate this problem in a deviated well.
Applying a weighted sweep program that targets the silt bed that accumulates on the low side of the hole can mitigate hole-cleaning problems that often occur in ERD wells. As early as 1986, hole-cleaning research indicated that turbulent flow produced by relatively thin drilling fluid is more effective at silt-bed removal than is flow produced under a high-viscosity flow profile. Consistent results in silt-bed removal have been achieved with fully-circulated, low-viscosity, weighted sweeps that exceed the drilling mud weight by 3 to 4 ppg and provide a 200- to 400-ft column in the annulus. The guidelines for an effective weighted sweep program are:
- The sweep is pumped at regular intervals at the normal circulating rate.
- The pipe-rotation speed is ≥ 60 rev/min once the sweep has reached the bit.
- The sweep is allowed to return to the surface with continuous circulation.
The additional buoyancy that a weighted sweep provides helps to reduce cuttings-settling tendency while the sweep travels up the annulus; however, the efficiency of the weighted sweep in dislodging cuttings might cause an increase in ECD while the annulus becomes loaded. If a PWD tool is used, effects on the ECD can be monitored and the pump rate reduced as needed to maintain an acceptable ECD without allowing cuttings to settle.
Barite sag can occur in high-angle wells (possibly at 35°, but increasingly likely at ≥ 50°, then diminishing as the interval approaches 75 to 90°). The most severe sag incidents typically occur in the 45 to 65° range. Sag causes a decrease in drilling-fluid density, which is particularly noticeable when circulating bottoms up after a long noncirculating period. The barite falls to the low side of the wellbore and slides toward the bottom, creating an accumulation of weighted silt around the lower part of the drillstring.
Barite sag can lead to well-control issues and stuck pipe and can aggravate hole-cleaning problems. A well-designed sweep program can help prevent or minimize the occurrence of sag. Recent field results indicate significant success in preventing sag using properly formulated weighted sweeps. When using an emulsion-based synthetic fluid that contains no commercial clays, operators have experienced little or no detectable barite sag, based on data retrieved from downhole pressure-sampling tools and drilling-fluid-density measurements recorded while circulating bottoms up., 
Salt Formations and Rubble Zones
The five major problems that typically are associated with drilling of salt formations are bit-balling and packoff because of reactive shales within the salt, wellbore erosion when drilling through the salt formation and/or through shales above or below the salt formation, excessive torque and packoffs caused by salt creep, well-control issues, and excessive mud losses. The rubble zone that might lie beneath or adjacent to the salt section usually consists of a series of highly reactive shale stringers that are embedded in unconsolidated sand. The zone could be overpressured at the entry point because of a gas pocket under the salt, then underpressured for the remainder of the section.
Catastrophic mud loss below the salt is the most challenging of these problems and prevents most operators from drilling rubble zones with OBFs and SBFs. The decision about whether to use an SBF or a salt-saturated WBF usually is based on the known risk of lost returns. The SBF can provide increased drilling efficiency and a faster ROP, but a salt-saturated WBF provides adequate control over hole enlargement and might be preferable where the potential for large losses exists. Seawater or undersaturated pills might facilitate ROPs without creating excessive washout, but extended use of undersaturated WBF might cause excessive hole enlargement where the longest exposure to the drilling fluid occurs.
Using hydraulics-modeling software and PWD data, a hydraulics baseline can be established while drilling through the salt formation and before reaching the rubble zone. If it is necessary to lay down the PWD tool before drilling through the rubble, this baseline can help the operator maintain a minimal ECD in the rubble zone.
Special Drilling Situations
Until the riser is in place, all drilling fluid returns to the seabed. A variety of drilling-fluid systems are available for drilling the top-hole riserless interval, including 1:1, 2:1, and 3:1 seawater/base-fluid blends; ballast-storable fluids; and precisely engineered "pad muds" for maintaining wellbore stability while running casing.
Typically, drilling fluid must be mixed and treated at flow rates of up to 1,000 U.S. gal/min (1,400 bbl/hr). A three-inlet, high-performance eductor often is used to blend riserless drilling fluids, which allows a third stream of CaCl2 or an alternate inhibitive brine to be mixed with standard seawater and base-fluid streams.
Using a specialized, polymer-free base fluid facilitates efficient pumpoff from supply boats. The ideal fluid is thin enough to be transported by a standard centrifugal pump, yet retains the desired rheological properties when blended with seawater.
For remote locations that do not have continuous workboat support, using a ballast-storable fluid system helps to ensure that the operator has access to the required volume of drilling fluid during inclement weather. The fluid should be virtually solids-free to help avoid settling in the tanks. This type of system has been used for the riserless portion in several deepwater operations.
Accurate modeling helps when formulating an optimal pad mud for each well. A properly designed pad mud helps to ensure that the wellbore will remain stable while surge pressures are minimized. Modeling-anticipated hole conditions allow the drilling-fluids engineer to predict the effects of interdependent parameters such as the maximum recommended ROP at various flow rates and cuttings concentrations; the ECD on the bottom and the annular cuttings concentration at different ROPs and flow rates; transport efficiencies and annular shear rates at different flow rates; and a comparison of proposed casing running speed with surge-pressure tolerances. The pad mud should exhibit controllable fluid-loss characteristics to minimize filter-cake buildup across permeable sands.
Drilling operations in water depths of between 5,000 and 10,000 ft take place all over the world, and their success underscores the adaptability of oilfield technology and the industry’s capacity to overcome significant technical challenges. The unique conditions presented by deepwater drilling require certain drilling-fluid characteristics. These are related to temperature variation, overpressured shallow water-bearing sands, narrow pore pressure/fracture gradient margins resulting from the extra fluid weight in the long drilling riser, and the potential for hydrates at the mudline.
The seafloor temperature in deepwater locations is approximately 40°F, but it can approach 32°F. The temperature downhole can exceed 300°F. The drilling fluid should exhibit the appropriate rheological properties throughout this wide range. In the riser near the mudline, the fluid is apt to thicken excessively from exposure to the cold seafloor temperature. Downhole, the fluid might become too thin as it heats up, and problems with hole cleaning and barite sag might develop. SBFs that contain little or no commercial clay appear to remain the most stable under these conditions. These clay-free and low-clay systems rely on emulsion characteristics to achieve the desired rheological properties and provide sufficient barite suspension.
Shallow-Water Flow (SWF)
Seismic data can help operators to predict and evaluate the risk of encountering an SWF on a given well. These water-bearing sands typically are located in the first 2,000 ft below the mudline and often are encountered while drilling in riserless mode. Stopping the flow under these circumstances is difficult. Pumping weighted mud that is cut with seawater on the fly generally is successful, but it requires pumping thousands of barrels of weighted WBF that returns to the seafloor because the riser is not yet connected to the wellbore. If the SWF is not brought under control or cased off successfully, its continued flow can undermine the structural integrity of the well and even affect neighboring wells.
Because of the long riser that is required in deepwater operations, the hydrostatic pressure from the column of drilling fluid can approach or exceed the fracture gradient, especially when breaking circulation after a static period, tripping in the hole, or running casing. Significant loss of whole mud can occur and might lead to well-control problems. Control of the ECD, as verified by PWD data, is critical to maintaining wellbore stability. The drilling fluid that is selected should be evaluated for its demonstrated capacity to minimize or eliminate whole-mud losses. A suitable fluid will be characterized in part by a comparatively small pressure spike on PWD logs when circulation is resumed after a long static period.
When a WBF is used, the cold seafloor temperatures coupled with high pressures can cause the formation of hydrates, or "dirty ice." Hydrates form from hydrogen bonding between water molecules and low-molecular-weight gas. The water actually forms a crystalline cage structure around the gas and creates the risk of blocking the choke and kill lines at the blowout preventers. The four conditions required for hydrate formation are the presence of gas, the presence of water, low temperature, and high pressure. Shutting in a gas influx on a deepwater well that is drilled with WBF makes a likely scenario for hydrate formation.
Maintaining the appropriate salinity level in the WBF suppresses hydrate formation. For extreme situations, glycerine, polyglycerine, and polyglycol products might be needed to further suppress the hydrate-formation temperature.
A well with a bottomhole temperature of >350°F generally is considered to be in the high-temperature category. Where possible, these wells are drilled with OBFs or SBFs because of the thermal limitations of most WBFs. Such limitations include temperature-induced gelation, high risk of CO2 contamination from the formation being drilled and/or from the degradation of organic mud additives, and increased solids sensitivity that is related to high temperatures.
Historically, WBFs have relied on bentonite clay for both rheology and filtration control. When tested at temperatures ≥ 300°F under laboratory conditions, bentonite slurries begin to thermally flocculate. Under HP/HT conditions with significantly elevated temperatures, a traditional WBF such as the lignosulfonate system might thicken so much that it no longer is usable or requires drastic and costly dilution and conditioning.
The ability to maintain bentonite and other active solids in a deflocculated state is the key to obtaining acceptable rheological and fluid-loss properties for WBFs exposed to high temperatures. Bentonite can be used in relatively low concentrations if it is supplemented with a high-temperature, high-molecular-weight synthetic polymer for additional carrying capacity. This combination helps to make it possible to maintain 6% by weight of low-gravity solids and a PSD of these solids in an acceptable micron range. Adding polymeric deflocculant at depths where elevated temperatures are expected assists in rheology control.
An HP/HT viscometer typically is used to monitor the temperature stability of the drilling fluid and to evaluate its rheological properties at up to 500°F and 20,000 psia. This test is especially useful for determining whether high-temperature flocculation occurs in water-based muds. The test results can be presented graphically by plotting the change in viscosity with respect to temperature over the heating and cooling cycle, which establishes a baseline for recognizing indicators of temperature instability.
Eliminating lignite and lignite derivatives from the WBF formulation, lowering the bentonite concentration, and supplementing the high-temperature water-based system with synthetic polymers and copolymers can help minimize problems with temperature gelation.
OBFs and SBFs are subject to temperature thinning. Surface density should be corrected on the basis of downhole pressure data from a PWD tool. Hydraulics-modeling software that accurately accounts for fluid compressibility and the effect of temperature can improve the performance of the SBF system by allowing more precise surface conditioning.
A prime objective in all drilling operations is to minimize safety and environmental risks while maintaining drilling performance. Operators and service companies alike take a proactive stance to reduce the potential for hazardous incidents and to minimize the impact of any single incident. The HSE policies of many companies are more stringent than those required by national governments and the various agencies charged with overseeing drilling operations. All personnel who take part in the well-construction process must comply with these standards to ensure their own safety and that of others. On most locations, a "zero-tolerance" policy is in effect concerning behaviors that might endanger workers, the environment, or the safe progress of the operation. Additionally, all personnel are encouraged to report potentially hazardous activities or circumstances through a variety of observational safety programs.
The packaging, transport, and storage of drilling-fluid additives and/or premixed fluid systems are closely scrutinized regarding HSE issues. Personnel who handle drilling fluid and its components are required to wear personal protective equipment (PPE) to prevent inhalation or other direct contact with potentially hazardous materials. Risk-assessed ergonomic programs have been established to reduce the potential for injuries related to lifting sacks and other materials and operating mud-mixing equipment.
When possible, drilling-fluid additives, base fluids, and whole mud are transported in bulk-tote tanks or are containerized. These transport methods help reduce packaging-related waste and minimize the risk of harming personnel, polluting the environment, and impairing operations. High-volume materials such as barite, bentonite, salt, and base fluids almost always are provided in bulk to offshore installations; onshore locations might use both bulk and packaged-unit materials, depending on the well depth and complexity.
The drilling-fluids specialist and operator representative at each location are responsible for ensuring that the available volume and properties of the drilling fluid will meet the immediate demands of a well-control situation, a loss of circulation, a tripping of a wet string, and/or a material-delivery delay caused by adverse transport conditions, and that additional volumes of drilling fluid with the appropriate properties can be mixed as needed at the rigsite or obtained in a timely manner. Published well-control guidelines recommend storing a riser volume plus 200 bbl (for pumping and line losses) in water depths ≥ 1,000 ft. Many deepwater-drilling operations take place in water depths exceeding this and approaching 10,000 ft. Nonsettling, ballast-storable drilling fluids have been used offshore to eliminate the risk of disruptions to supply created by inclement weather and to prepare for drilling through SWFzones.
Protecting the EnvironmentKeeping drilling-related accidents to "few and far between" not only provides the obvious benefit of minimizing, if not eliminating, sources of pollution and related threats to the ecosystem, but also enables the oil and gas industry more easily to obtain governmental permission to acquire and develop commercial reserves worldwide.
The drilling activities of countries that are emerging as energy producers should reflect the successful practices established by operators in well-regulated areas, as outlined in Table 2.3, which is modified from the CAPP Technical Report 2001-0007. The associated technologies, procedures, financial arrangements, and records serve as project blueprints for newcomers to the industry. Developing nations can better protect their natural environments and resources by implementing proven standards. Environmental-protection agencies and industry associations worldwide continue to study the effects on air and water quality had by drilling-fluid- and cuttings-related discharges specifically and by drilling operations generally.
Attention to international environmental issues often is channeled through the Intl. Assn. of Oil and Gas Producers (OGP), the membership of which consists of 45 oil companies, 10 industry associations, and 2 service companies operating in more than 80 countries. The OGP Environmental Quality Committee addresses drilling fluids and cuttings, environmental-performance indicators, and related regulatory issues.
The United Kingdom Offshore Operators Assn. (UKOOA) and the Oljeindustriens Landsforening /Norwegian Oil Industry Association (OLF), a corresponding Norwegian organization, have been formally examining the effects of drill-cuttings beds in the central and northern North Sea since June 1998. Nearly U.K. £5 million was budgeted to assess the environmental impact of existing cuttings beds, compare options for accelerating degradation, and investigate the risks associated with removing the beds mechanically.
In the United States, an API report on environmental protection indicates that in 2000, the U.S. oil-and-gas industry spent $7.8 billion in this area, an amount that represents approximately 10% of the net income of the top 200 oil and natural gas companies. Since such record keeping began in 1992, the oil-and-gas industry has spent an estimated $90 billion to protect that nation’s environment.
Drilling-fluid companies strive to maintain an "econo-ecological" balance when choosing drilling-fluid systems and additives. An ecologically friendly drilling-fluid system that performs poorly will be used seldom because its poor performance extends drilling time and increases both the likelihood of hole problems and the cost of well construction. Conversely, using a properly managed high-performance SBF can shorten the duration of the drilling operation and/or help maintain wellbore stability, thereby reducing opportunities for environmental damage. These and other factors must be weighed in the selection and design of any drilling-fluid system.
Sources of Contamination
Land and offshore drilling locations are regulated regarding the disposal of whole mud, drilled cuttings and other solids, and runoff generated by rainfall, wave action, or water used at the rigsite. Industrywide efforts to eliminate environmental hazards resulting from accidents or the negligent handling of drilling fluids and/or drilled cuttings encompass several contamination issues related to drilling fluids: formulation (chlorides, base oils, heavy metals, and corrosion inhibitors), natural sources (crude oil, salt water, or salt formation), and rigsite materials (pipe dope, lubricants, and fuel).
In some cases, reformulating drilling-fluid systems makes them environmentally more benign. For example, chrome lignosulfonate WBF is available in a chrome-free formulation. The development of SBFs stemmed from the need to replace diesel- and mineral-oil-based fluids (OBFs) because of environmental restrictions.
The discharge of conventional OBFs and drilled cuttings effectively was prohibited in the North Sea in 2000. According to the OsloParis Convention (OSPAR) Commission for the Protection of the Marine Environment of the North-East Atlantic, 98% of the total hydrocarbon discharge volume consists of produced water and drilled cuttings generated with SBFs.
Cuttings that are generated by drilling with certain compliant SBFs may be discharged overboard in the western Gulf of Mexico if they comply with the retention-on-cuttings (ROC) limits introduced in 2002 by the U.S. Environmental Protection Agency (EPA). Neither traditional OBFs nor the drilled cuttings produced while using them can be discharged in the Gulf of Mexico; the rare offshore operation that uses a diesel- or mineral-based fluid must include a closed-loop process for continuously capturing all drilled cuttings and returning them to shore for regulated disposal.
Gulf-of-Mexico Compliance-Testing ProfileIn deciding to permit the use of SBFs rather than restrict operators to WBFs, the EPA acknowledged the importance of the econo-ecological balance. The EPA felt that switching solely to WBF would cause more WBF development wells and more discharges to the ocean because WBF operations produce more waste per well than do SBF wells. WBF and OBF operations also progress more slowly than do SBF operations, leading to increased air emissions and fuel usage. Furthermore, the technical demands of drilling in deepwater locations require the use of either an SBF or OBF, and the pollution risks from a riser disconnect where OBF is in use are far greater than with SBF. Therefore, SBFs became the generally approved fluids for the Gulf of Mexico.
The toxicity of a drilling fluid and/or of cuttings that are generated with the fluid is determined by the fluid composition and is measured using a variety of testing protocols. Table 2.4 lists tests that the 2002 modifications to the EPA General Permit require to be performed where SBF is used. Discharge of whole SBF is prohibited. Unblended linear paraffin and LAO base fluids are not expected to comply with the modified requirements because of biodegradation and/or toxicity issues.
Although technical advances in the design and formulation of SBFs have been spurred mainly by offshore drilling conditions, the biodegradability and relatively low toxicity of ester- and IO-based fluids make them suitable for onshore operations as well. Experimentation with various soil types, plant germination, and earthworm survival rates indicates that these base oils respond well to bioremediation.
Solids Control and Waste Management
Contamination of drilling fluids with drilled cuttings is an unavoidable consequence of successful drilling operations. If the drilling fluid does not carry cuttings and cavings to the surface, the rig either is not "making hole" or soon will be stuck in the hole it is making. Before the introduction of mechanical solids-removal equipment, dilution was used to control solids content in the drilling fluid. The typical dilution procedure calls for dumping a portion of the active drilling-fluid volume to a waste pit and then diluting the solids concentration in the remaining fluid by adding the appropriate base fluid, such as water or synthetic oil.
Using solids-control equipment to minimize dilution has been a standard practice for the drilling industry for more than 60 years. Equipment and methods have changed over that time, but the fundamentals behind the process have not:
- Solids concentration matters—increasing solids content is detrimental to fluid performance.
- Economics matter—mechanical removal of solids costs less than dilution.
- Volume matters—the volume of waste generated is indicative of performance.
- Size matters—fine solids are the most detrimental and difficult to remove.
- Stokes’ law matters—viscosity and density affect gravity separations.
- Shaker-screen selection matters—shaker screens make the only separation based on size.
- Footprint matters—the space available for equipment on rigs always is limited.
Increasing solids concentration in drilling fluid is a problem for the operator, the drilling contractor, and the fluids provider. It is well established that increasing solids content in a drilling fluid leads to a lower ROP. Other problems that are related to excessive solids concentration include:
- High viscosity and gel strength.
- High torque and drag.
- Lost circulation caused by higher ECD.
- Abrasion and wear on pump fluid ends.
- Production loss caused by formation damage from filtrate or solids invasion.
- Stuck pipe caused by filtrate loss.
- Poor cement jobs caused by excessive filter cakes.
- Generation of excessive drilling waste.
- Higher drilling-fluid maintenance costs.
Particle Size and Surface Area
From the perspective of both the drilling-fluids specialist and the solids-control technician, the effects of particle size and surface area are perhaps the most important concepts to understand. The fluids industry describes particle size in microns.
One micron (μm) is one one-thousandth of a meter and is equivalent to one inch divided by 25,400. The visual acuity of an unaided eye is approximately 35 μm, and fingertip sensitivity is approximately 20 μm. Drilled solids vary in size from < 1 μm to 15,000 μm in average particle diameter. Colloidal-sized particles are< 2 μm (average particle diameter) and will not settle out under gravitational forces. Ultrafines range from 2 to 44 μm and are unlikely to settle out of a drilling fluid unless it is centrifuged.
Solids of colloid and ultrafine size have the most adverse effect on fluid rheology. Ultrafines and colloids have pronounced effects on mud properties because both particle types have large surface-to-volume ratios. Like bentonite particles, the exposed surfaces of fine drilled solids contain charges that increase the viscosity and gel strengths of the drilling fluid. Unlike bentonite, drilled solids do not plate out on sides of the wellbore to form a compressible and slick filter cake. The viscosity and fluid loss properties of a drilling fluid are difficult to control with high concentrations of drilled solids that are<
Fluid-technology advances have solved many of the problems that contribute to fines buildup in drilling fluids. Today, fluids are highly inhibitive and prevent cuttings dispersion like that shown in Fig. 2.2; however, the fluids cannot prevent cuttings recirculation or the inherent mechanical degradation that occurs during recirculation. Drilled solids that circulate through the mud tanks and back downhole are subject to mechanical degradation from surface pumps, drillpipe rotation, mud motors, and the bit’s jet nozzles. The solids-control equipment must remove solids as far upstream as possible in the surface drilling-fluid system. When drilled solids have degraded to ultrafines or colloids, it is increasingly difficult to remove them by mechanical separation or settling.
Separation by Settling
Hydrocyclones, centrifuges, and settling tanks rely on settling velocity to concentrate and separate solids from slurry. Settling velocity is described mathematically by Stokes’ law (Eq. 2.1), which states that the velocity at which a particle will settle in a liquid is proportional to the density difference between the particle and the liquid, the acceleration, and the square of the particle diameter. The settling velocity is inversely proportional to the viscosity of the liquid or slurry.
where Vs = the settling velocity because of G-force, d = the particle diameter, ρp = the density of the particle, ρl = the density of the liquid, g = the acceleration or G-force, and η = the viscosity of the liquid.
Because particle diameter is squared, it has a great effect on separation efficiency; however, other factors that affect the settling rate should not be overlooked. For example, if a fluid contains both high-gravity solids (HGS) and low-gravity solids (LGS), a centrifuge that recovers barite particles in the 10-μm range also will recover LGS particles in the 15-μm range because both settle at the same rate. It also follows from Stokes’ law that the settling velocity is lower in viscous and dense fluids; therefore the cut point and the capacity of centrifugal separators will be adversely affected by increasing viscosity and density.
Obviously, shale-shaker screens are important for controlling the concentration of LGSs. What often is overlooked is the impact that proper screen selection can have on the other functions of a mud system:
- Screens are the only solids-control devices that are changed to handle changes in fluid properties or drilling conditions.
- Screens generate the bulk of drilling waste and reclaim the bulk of the mud.
- Screens must be able to handle the full circulation rate.
- Screens are the only devices on a rig that separate solids on the basis of size.
The combined waste volume of cuttings that are created while drilling and the excess or spent drilling fluid might be the best measure of performance and cost savings offered by a fluids system. The volume of spent mud determines what the mud-maintenance and disposal costs are and affects the long-term liabilities that are associated with waste disposal. Even under ideal situations, the volume of wet cuttings generated can easily exceed hole volume by a factor of two or more (three is a good rule of thumb). Minimizing the volume of spent mud and cuttings is the key to effective waste management. The increase in volume of the wet cuttings stems only partly from the added volume of cavings, washouts, or drilling a nongauge hole.
Cuttings are not discharged from mechanical separators as dry particulate matter. Much of the volume increase comes from the effect of surface-to-volume ratio. As drilled cuttings are ground down by the bit or dispersed from fluid interaction, they become thoroughly wetted with the drilling fluid. This fluid is known as ROC and is difficult to remove mechanically. Furthermore, a certain amount of carrier fluid usually discharges from mechanical separators with the cuttings. Unless measures are taken to dry the cuttings, the volume of drilled cuttings that is discharged will be more than double that of the theoretical gauge hole. Hydrocyclones in particular discharge very wet cuttings. The volume of spent mud that is created will depend largely on mechanical solids-removal efficiency.
Total Fluids Management
The importance of viewing fluids, solids control, and waste management as a process that must be designed to meet specific drilling conditions cannot be overemphasized. This process design is the key to helping improve the economics and minimizing the environmental impact of drilling activities. Many operators prefer a total fluids management approach that integrates fluids, solids control, and waste management to deliver a cost-effective wellbore in a safe and successful manner.
During the project planning stage, the following questions should be asked to help ensure successful field operations:
- What equipment best suits the drilling-fluid program and waste-disposal options?
- What are the solids loading and liquid loading that the equipment must handle?
- How much time will it take to install equipment, and who will install it?
- Are pumps, piping, chutes, conveyors, etc., adequate for the intended service?
- Is there enough power on the rig for the proposed equipment set?
- Is space available to install the proposed equipment set?
- Can the drilling-fluid program be modified to assist the mud- and cuttings-treatment system?
- What information needs to be collected and reported?
- What training needs to take place before startup?
- What safety issues need to be addressed?
- What environmental issues need to be addressed?
- What contingency or emergency operations need to be planned?
Drilling-fluid selection remains one of the most important components of a successful well-construction operation. Drilling-fluid service companies strive to provide the analytical tools, test equipment, stockpoint facilities, and innovative materials that will help operators to overcome the familiar issues (e.g., lost circulation) as well as the challenges that are brought on by drilling in ultradeep waters, extreme HP/HT formations, or remote environmentally sensitive areas.
The ability to simulate downhole conditions and optimize fluid design will continue to help reduce nonproductive time, and real-time management of hole conditions through data feed from downhole tools allows the operator and drilling-fluid specialist to fine-tune drilling parameters.
The demand for drilling-waste-management services that are dedicated to reducing, recovering, and recycling the volume of spent fluids and drilled cuttings continues to grow rapidly. These services and the related equipment have demonstrated their worth by helping operators achieve environmental compliance, reducing disposal costs, and returning more fluid and water for reuse in multiple applications.
Drilling-fluid services of some kind are required on every well. They encompass a broad spectrum of systems, products, software, personnel specializations, and logistical support. As wells become more complex, total drilling costs can increase dramatically. Because the drilling-fluid system comes in contact with almost every aspect of the drilling operation, proper drilling-fluid selection can help the operator minimize costs throughout the well-construction process.
|d||= particle diameter, L, μm|
|g||= acceleration or G-force (constant 980 cm/s2), L/t2|
|η||= viscosity of the liquid, m/Lt, cp|
|Vs||= settling velocity because of G-force, L/t, cm/s2|
|ρl||= density of the liquid = SG|
|ρp||= density of the particle = SG|
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SI Metric Conversion Factors
|bbl||×||1.589 873||E – 01||=||m3|
|ft||×||3.048*||E – 01||=||m|
|ft 2||×||9.290 304*||E – 02||=||m2|
|ft 3||×||2.831 685||E – 02||=||m3|
|°F||(°F – 32)/1.8||=||°C|
|°F||(°F + 459.67)/1.8||=||K|
|U.S. gal||×||3.785 412||E – 03||=||m3|
|hp||×||7.460 43||E – 01||=||kW|
|in.||×||2.54*||E + 00||=||cm|
|in.2||×||6.451 6*||E + 00||=||cm2|
|in.3||×||1.638 706||E + 01||=||cm3|
|lbm||×||4.535 924||E – 01||=||kg|
|oz||×||2.957 353||E + 01||=||cm3|
|psi||×||6.894 757||E + 00||=||kPa|
Conversion factor is exact. <div/>